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fax 01-972-952-9435. AbstractOil identification and quantification in low resistivity laminated sand-shale sequences is a major challenge for petrophysics and reservoir engineers; essentially because the thickness of the sand laminas is usually bellow the vertical resolution of the resistivity logging tool. The presence of this lithology generates electrical anisotropy where horizontal resistivity is highly affected by the conductivity of the laminar shale volume, while vertical resistivity is higher and more sensitive to the laminar sand electrical properties. Once identified the productive low resistivity problem the prediction of movable water, creates enormous uncertainty when it comes to decide if this laminated sand should be open to production in the well. All this issues have caused the underestimation of Oil-In-Situ volumes and the lost of thousands of oil production per day in the upper Misoa Formation Reservoirs in western Venezuela. The incorporation of resistive image logs in the geological analysis of upper Misoa Reservoirs, have shown the existence of thinly laminated sand-shale sequences with laminations of an inch thick and less. indicated that 90% of the water contained in the reservoir was irreducible, so it would not be produced.After completing the low resistive sands, production logging tests and well production showed 1300 BBD with 4% of water. This case opened a great opportunity in western Venezuela fields where this type of lithology can be found in most of the wells drilled trough Eocene reservoirs.
fax 01-972-952-9435. AbstractOil identification and quantification in low resistivity laminated sand-shale sequences is a major challenge for petrophysics and reservoir engineers; essentially because the thickness of the sand laminas is usually bellow the vertical resolution of the resistivity logging tool. The presence of this lithology generates electrical anisotropy where horizontal resistivity is highly affected by the conductivity of the laminar shale volume, while vertical resistivity is higher and more sensitive to the laminar sand electrical properties. Once identified the productive low resistivity problem the prediction of movable water, creates enormous uncertainty when it comes to decide if this laminated sand should be open to production in the well. All this issues have caused the underestimation of Oil-In-Situ volumes and the lost of thousands of oil production per day in the upper Misoa Formation Reservoirs in western Venezuela. The incorporation of resistive image logs in the geological analysis of upper Misoa Reservoirs, have shown the existence of thinly laminated sand-shale sequences with laminations of an inch thick and less. indicated that 90% of the water contained in the reservoir was irreducible, so it would not be produced.After completing the low resistive sands, production logging tests and well production showed 1300 BBD with 4% of water. This case opened a great opportunity in western Venezuela fields where this type of lithology can be found in most of the wells drilled trough Eocene reservoirs.
The log evaluation of an expelling source rock is notoriously challenging because the kerogen and the generated oil coexist in the source rock. The Athel silicilyte is both an overpressured light-oil reservoir and a world-class source rock. In this unique geological setting found in the South Oman Salt Basin, reservoir characterisation is intimately associated with source rock evaluation. In the absence of any direct geological analogue, the initial petrophysical model was calibrated against extensive core analyses. Porosity interpretation was then based exclusively on wireline bulk density measurements. The limitations of this approach only became apparent as attempts to reconcile data from various sources failed. While efforts aimed at obtaining representative core material and establishing reliable core analysis procedures, in-situ calibration of the petrophysical model was also actively pursued. NMR logging was primarily introduced to reduce uncertainties affecting density-derived porosities in the presence of variable, unknown organic matter content. The first NMR log run in a silicilyte well could not be fully reconciled with density data. Laboratory NMR confirmed the log measurements, but more questions were raised when significant NMR signal was recorded on dry, cleaned samples at the time when new field data could not be explained. Athel silicilyte is unique, and with no reference to confirm or to invalidate new data and interpretation, consistency and integration are key to improving our understanding of the rock. A thorough review of NMR acquisition procedures and processing algorithms was undertaken with logging contractors; job planning was improved, new logging procedures were implemented, tool malfunctions were identified and remedied, processing methods were upgraded. Laboratory procedures were revisited, and NMR core measurements were complemented with additional, independent core analyses. Whereas the initial emphasis was on "effective" porosity determination, NMR logs and core measurements provided new insight into the Athel silicilyte rock. This includes:strong indications that the rock may be mixed-wet;encouraging results in the area of permeability estimation; andindeed higher confidence in the assessment of effective porosity. A TOC (Total Organic Carbon) log can also be derived, which could find further application in source rock evaluation and the characterisation of organic-rich reservoirs. Integration of all available log data using a statistical approach now provides a consistent reservoir description, with limited core calibration requirements. Having successfully integrated NMR data to unravel the organic content of the rock, the improved petrophysical model provides the basis for sound reservoir characterisation, the foundation for better exploration, appraisal and development decisions. Introduction The Athel play has been the object of much exploration effort in Petroleum Development Oman (PDO). In 1997, an integrated asset team, the first in PDO, was established to demonstrate the commerciality of Al Noor, the first Athel discovery where six wells have now established 190.106 m3 oil in place. As plans to develop the field matured, the focus shifted from regional studies to reservoir characterisation. At the same time, the objectives of well evaluations evolved from a stand-alone assessment of average porosity, net-to-gross, and saturation towards the determination of the vertical and lateral distribution of reservoir properties. Accurate porosity evaluation is a key element in this context. After briefly reviewing the foundations of the original porosity model established to evaluate Athel silicilyte wells, this paper shows how NMR is being used to improve the assessment of porosity from wireline logs. The details of the experience gained in the application of laboratory and wellbore NMR technology to Athel silicilyte are presented. The Al Noor Discovery The Al Noor accumulation is located in the South Oman Salt Basin. There, the 400-m thick Athel silicilyte is encased in salt at around 4200 m depth. Silicilyte is not a term used frequently outside of PDO or its contractors. However, it has been defined previously[1] as "… a sedimentary rock composed principally of siliceous remains of organisms". The reservoir potential of this unique rock was not recognised until 1989, when the Al Noor-l exploration well proved the producibility of hydrocarbons from the Athel "source rock".
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA new magnetic resonance fluid (MRF) characterization method for fluids in porous rocks has been developed. The method uses suites of spin-echo measurements that can be acquired in the laboratory or by a nuclear magnetic resonance (NMR) logging tool. In general, the data suites consist of spinecho measurements with different echo spacings, polarization times, applied magnetic field gradients, and numbers of echoes. These measurements are sensitive to the viscosities and molecular diffusion coefficients of the fluids and therefore provide the information needed for fluid characterization.The MRF method is based on the inversion of a general multifluid relaxational model that describes the decay of the transverse magnetization in porous rocks containing reservoir fluids. In its most general form, the relaxational model consists of separate contributions to the measured spin-echo signals from all of the fluids that can be present in reservoir rocks; i.e., brine, oil, gas, and oil-base mud filtrate (OBMF), including mixtures of gas dissolved in oil or OBMF. A key ingredient in the multifluid relaxational model is a new phenomenological microscopic constituent viscosity model (CVM) for hydrocarbon mixtures that links diffusion-free relaxation and molecular diffusion in crude oils. The CVM significantly improves the robustness of the inversion so that accurate fluid characterization is possible even when the brine and crude oil T 1 and T 2 distributions overlap one another. We a Present address: Dept. of Chem. Eng., Rice University. b Present address: Schlumberger Sugar Land Product Center. present experimental results on live and dead hydrocarbon mixtures and crude oils that confirm the validity of the CVM.The results of a Monte Carlo simulation for a model carbonate formation containing brine, crude oil, gas, and OBMF demonstrate the robustness and accuracy of the inversion. Monte Carlo simulations conducted for different types of rocks containing different amounts and types of fluids demonstrate that the inversion provides quantitative estimates of total porosity, fluid saturations, fluid volumes, bulk volume irreducible water, crude oil viscosity, hydrocarbon-corrected permeability, crude oil T 1 and T 2 relaxation time distributions, crude oil diffusion coefficient distributions, brine T 2 distributions, and apparent brine T 1 /T 2 ratios.The MRF method was also tested in the laboratory on partially saturated Berea 100 and Indiana limestone rocks containing brine and oil. The water saturations estimated from the NMR data by inversion of the multifluid relaxational model are shown to agree well with the water saturations that were independently estimated from differential weight measurements. The oil viscosity estimates are also shown to be in good agreement with the known viscosity of the oil.
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